This invention relates generally to offshore well drilling operations. More particularly, the invention pertains to gas-lifted risers for use in drilling offshore wells. Specifically, the invention is a method and apparatus for controlling the riser base pressure and detecting well control problems, such as kicks or lost circulation, during drilling of an offshore well using a gas-lifted riser.
In recent years the search for offshore deposits of crude oil and natural gas has been moving into progressively deeper waters. In deep waters, it is common practice to conduct drilling operations from floating vessels or platforms. The floating vessel or platform is positioned over the subsea wellsite and is equipped with a drilling rig and associated drilling equipment.
To conduct drilling operations from a floating vessel or platform, a large diameter pipe known as a xe2x80x9cdrilling riserxe2x80x9d is typically employed. The drilling riser extends from above the surface of the body of water downwardly to a wellhead located on the floor of the body of water. The drilling riser serves to guide the drill string into the well and provides a return conduit for circulating drilling fluids.(also known as xe2x80x9cdrilling mudxe2x80x9d or simply xe2x80x9cmudxe2x80x9d).
An important function performed by the circulating drilling fluids is well control. The column of drilling fluid contained within the wellbore and the drilling riser exerts hydrostatic pressure on the subsurface formation which overcomes formation pore pressure and prevents the influx of formation fluids into the wellbore, a condition known as a xe2x80x9ckick.xe2x80x9d However, if the column of drilling fluid exerts excessive hydrostatic pressure, the reverse problem can occur, i.e., the pressure of the drilling fluid can exceed the natural fracture pressure of one or more of the exposed (i.e., uncased) subsurface formations. Should this occur, the hydrostatic pressure of the drilling fluid could initiate and propagate a fracture in the formation, resulting in drilling fluid loss to the formation, a condition known as xe2x80x9clost circulation.xe2x80x9d Excessive fluid loss to one formation can result in loss of well control in other formations being drilled, thereby greatly increasing the risk of a blowout. Thus, proper well control requires that the hydrostatic pressure of the drilling fluid adjacent an exposed formation be maintained above the formation""s pore pressure, but below the formation""s natural fracture pressure.
For a conventional offshore drilling system in which the drilling fluid contained in the wellbore and the drilling riser constitutes a continuous fluid column from the bottom of the well to the surface of the body of water, it is increasingly difficult, as water depth increases, to maintain the pressure of the drilling fluid in the wellbore between the formation pore pressure and the natural fracture pressure of the exposed formations. This problem is well known in the art. See, e.g., Lopes, C. A. and Bourgoyne, A. T., Jr., Feasibility Study of a Dual Density Mud System for Deepwater Drilling Operations, OTC 8465, Offshore Technology Conference, May 5-8, 1997. Because of this problem, the allowable length of exposed borehole is severely limited and frequent installations of protective casing strings are required. This, in turn, results in longer times and higher costs to drill the well.
It has long been recognized that one solution to this problem is to maintain the drilling fluid pressure at the wellhead (i.e., at the elevation of the floor of the body of water) approximately equal to that of the surrounding seawater. This effectively eliminates the problems resulting from the fact that drilling fluid typically has a higher density than seawater. Several methods of accomplishing this have been proposed, including injection of a gas (xe2x80x9clift gasxe2x80x9d) such as nitrogen into the lower end of the drilling riser. Lift gas injected into the drilling riser intermingles with the returning drilling fluid and reduces the equivalent density of the column of drilling fluid in the riser to that of seawater. The column of drilling fluid in the well below the lift gas injection point does not contain lift gas and, accordingly, is denser than the drilling fluid in the riser. Hence, this approach provides a xe2x80x9cdual densityxe2x80x9d circulation system. U.S. Pat. No. 3,815,673 (Bruce et al.) discloses an example of such a xe2x80x9cgas-lifted drilling riserxe2x80x9d in which an inert gas is compressed, transmitted down a separate conduit, and injected at various points along the lower end of the drilling riser. Bruce et al. also disclose a control system responsive to the hydrostatic head of the drilling fluid which controls the rate of lift gas injection into the riser in order to maintain the hydrostatic pressure at the desired level.
U.S. Pat. No. 3,603,409 (Watkins) illustrates a variation of the gas-lifted drilling riser concept in which the drilling riser is replaced by a separate drilling fluid return conduit. The drill string enters the well through a rotating blowout preventer (BOP) located on top of the subsea wellhead, and alternate means for guiding the drill string into the well are provided. According to Watkins, lift gas is injected into the wellhead in an amount sufficient to cause the density of the drilling fluid in the separate return conduit to approximate the density of seawater.
Unfortunately, two major problems have prevented practical application of gas-lifted risers. The first is pressure control. Simulations and tests of the behavior of gas-lifted risers have shown that it is extremely difficult to maintain a constant value of the riser base pressure (prb) due to unavoidable variations in the flow rate or density of the drilling fluid in the riser. An example of such unavoidable variation is the interruption of flow required to add a length (joint) of drill pipe to the drill string as the well is drilled deeper. Riser base pressure (prb) is the integrated result of the varying density of the entire column of drilling fluid and lift gas in the riser and is particularly influenced by the rapidly expanding lift gas near the top of the riser. The effects on prb of a momentary (i.e., two to three minutes) change in flow conditions at the base of a gas-lifted riser in 10,000 feet (3,048 meters) of water will persist for as long as about an hour and a half as the affected xe2x80x9cpacketxe2x80x9d of drilling fluid and lift gas moves up the riser. The largest effect occurs as the mixture approaches the surface. Therefore, simply sensing prb and adjusting the lift gas flow rate to respond to drilling fluid flow changes over intervals of several minutes leads to large instabilities in prb.
The second major problem that has prevented practical application of gas-lifted risers is detection of well control problems such as kicks and lost circulation. It is well known that the most sensitive method of detecting kicks or lost circulation is to measure the rate of return flow of drilling fluid from the well and to compare it with the rate of flow of drilling fluid being pumped into the well via the drill pipe (see e.g., Maus, L. D., et al., Instrumentation Requirements for Kick Detection in Deep Water, Journal of Petroleum Technology, August 1979, pp. 1029-34). This may readily be accomplished provided the volume of fluid in the circulation system between the points of measurement of the input and return flow rates is constant or known. However, with a gas-lifted riser upstream of the return flow measurement point, there is the potential for unknown and varying volumes of fluid in the circulation system due to the presence of lift gas in the riser. This uncertainty significantly impedes the early detection of kicks or lost circulation.
In the late 1970s, two approaches to controlling gas-lifted drilling risers were proposed. U.S. Pat. No. 4,091,881 (Maus ""881) envisioned diverting the return flow of drilling fluid from the upper portion of the drilling riser, through a throttling valve, and into a separate return conduit where the lift gas was injected. The rates of lift gas injection into the return conduit and drilling fluid withdrawal from the drilling riser were controlled to maintain the hydrostatic pressure of the drilling fluid remaining in the drilling riser and wellbore at or below the fracture pressure of the formation. This method has the disadvantage of requiring one or more separate conduits for returning the drilling fluid to the surface and the continuous use of a throttling valve in very severe service (drilling fluid with cuttings).
U.S. Pat. No. 4,099,583 (Maus ""583) disclosed a variation of the gas-lifted drilling riser concept which used a seawater-based drilling fluid. According to this variation, lift gas is injected into the drilling fluid to provide the lift necessary to return the drilling fluid to the surface and to reduce its density. Lift gas injection is maintained at a rate that overlifts the drilling fluid to the extent that the hydrostatic pressure of the drilling fluid is reduced to less than that of the ambient seawater surrounding the drilling riser. Seawater is permitted to flow into the lower end of the riser in response to the differential pressure between the drilling fluid and the seawater so that the pressure of the drilling fluid becomes approximately equal to that of the ambient seawater. The method disclosed in the Maus ""583 patent applies only to drilling the upper part of an offshore well where seawater may be used as the drilling fluid. This method would not be suitable for drilling fluids based on fresh water, oil, or synthetic fluids (such as are typically used in drilling the deeper portions of offshore wells) because of contamination with seawater.
More recently, a gas-lifted drilling riser system was described by workers at Louisiana State University (Lopes et al., supra). With respect to the problem of pressure control during drill pipe connections, Lopes et al. stated that xe2x80x9c[t]he foreseen solution to this problem is to keep the gas injection going, but at a much lower rate, determined by the automatic controller, equal to the rate with which the gas is migrating.xe2x80x9d Unfortunately, as noted above, adjusting the lift gas flow rate to respond to drilling fluid flow changes over intervals of several minutes can lead to large instabilities in the riser base pressure (prb). Lopes, et al. also briefly discuss a variety of kick detection techniques, none of which is believed to be as sensitive, reliable, and practical as that of the present invention.
Another potential solution to the problems encountered in drilling offshore wells in deep waters is disclosed in U.S. Pat. No. 4,813,495 (Leach). According to Leach, drilling fluid returns are taken at the seafloor, and the drilling fluid is then pumped to the surface through a separate return riser by a centrifugal pump that is powered by a seawater driven turbine. The drill string enters the well through a rotating pressure head located on top of the subsea wellhead. By taking the drilling fluid returns at the seafloor, the pressure of the drilling fluid column in the return riser is removed from the formation. Unfortunately, the large subsea pumps used to pump the drilling fluid from the seafloor back to the surface are quite expensive and difficult to maintain. Moreover, the absence of a conventional drilling riser means that it is not possible to revert to normal drilling operations if problems are encountered.
From the foregoing, it can be seen that there is a need for an improved method and apparatus for controlling pressure and detecting well control problems with a gas-lifted riser. Such method and apparatus should be capable of maintaining the riser base pressure (prb) relatively constant despite unavoidable variations in drilling fluid flow rate or drilling fluid density. Such method and apparatus should also be capable of quickly and accurately detecting kicks or lost circulation. The present invention satisfies this need.
The present invention is a method and apparatus for controlling the pressure at the base of a gas-lifted riser during drilling of an offshore well. Preferably, the internal pressure at the base of the riser should be maintained approximately equal to the ambient seawater pressure at that depth despite variations in the flow rate and/or density of the well return flow. The invention may also be utilized to detect well control problems, such as kicks or lost circulation, during drilling of an offshore well using a gas-lifted riser.
In one embodiment, the inventive pressure control system comprises two complementary control elements. The first element adjusts the pressure at the surface and the mass flow rate out of the top of the riser to compensate for changes in riser base pressure due to variations in the mass flow rate entering the riser. The second element adjusts either or both of the boost mud flow rate and the lift gas flow rate to maintain a substantially constant mass flow rate entering the riser. In some situations, either the first element or the second element alone may provide satisfactory control.
The pressure control system operates by measuring a number of operating parameters of the gas lift system and, based on these measurements, calculating the adjustments necessary to maintain the riser base pressure within the desired control range. The invention also compares the well return flow rate (i.e., the flow rate prior to the injection of lift gas or boost mud) to the drill string flow rate so as to detect well control problems. Preferably, these control operations are performed on a substantially continuous basis throughout the gas-lifting operation. Alternatively, the control operations may be performed on a frequently recurring basis, at regular or irregular intervals.
The inventive pressure control system may be used in conjunction with either a gas-lifted drilling riser or a separate gas-lifted mud return riser. The pressure control system may be utilized in any water depth, but is especially advantageous in extremely deep waters (i.e., waters deeper than about 5,000 feet (1,524 meters)).